Enormous industrial and technical efforts have been exhausted with varying degrees of success grappling with the problem of environmental pollution generated from the processing of carbonaceous material. For example, the combustion of coal has provided the backbone of industrial and energy since the start of the industrial revolution. It is estimated that the world currently consumes over 4050 MT of coal per year. Such coal is utilized by a variety of sectors including: power generation; iron and steel production; cement manufacturing; and as a liquid fuel. For example, it is currently estimated that approximately 45% of all US electrical production is derived from coal combustion, while coal-fired power plants generate approximately 40-50% of global electricity. In some countries, coal generates an even higher percentage of electricity. For example, China produces approximately 80% of its electrical output from coal combustion, while South Africa generates over 90% of its total electricity from coal.
Despite renewed emphasis on alternative energy sources, with the existence of significant coal resources around the world capable of meeting large portions of the world's energy needs into the next two centuries, coal remains and will continue to be a core energy source. However, despite its prevalence, there exist various environmental and regulatory concerns, specifically related to the emission of harmful and unwanted chemical compounds generated from the combustion process. Apart from being one of the largest worldwide anthropogenic sources of carbon dioxide, coal combustion is a significant source of NOx, SOx and elemental as well as oxidized Hg and other heavy metals. (As described hereafter, carbonaceous material emissions may also be generally referred to as “Carbon Combustion by-Product's” (CCB's).) Such CCB emissions generally require remediation steps to prevent their release into the atmosphere upon combustion. For example, the emissions of SOx and NOx from U.S. power plants are regulated as part of Title IV of the Clean Air Act Amendments of 1990 (CAAA). (It should be noted that the purpose of this application, the term NOx generally encompasses all reactive compounds and/or gases which contain nitrogen and oxygen in varying amounts, such as nitrogen oxides. The term SOx generally encompasses all reactive compounds and/or gases which contain sulfur and oxygen in varying amounts, such as sulfur oxides. However, the terms NOx and SOX may also encompass any nitrogen or sulfur containing emission generated during the combustion, gasification or other processing method of carbonaceous materials respectively.)
As detailed below, such traditional systems are limited in their effectiveness as well as cost. Clearly an inexpensive, comprehensive solution to the aforementioned problems would represent a significant leap forward in the industry. One area of development is the use of additives that may facilitate non-formation and/or removal of emissions resulting from the consumption of carbonaceous and/or feedstock based processes as discussed above. By way of example, several U.S. patents have been issued relating to coal combustion byproduct removal. However, the present invention overcomes many of the operational and cost disadvantages associated with current processes involving pre-combustion additives. For example, past efforts to develop pre-combustion additives to coal, such as U.S. Pat. Nos. 7,988,939, 7,758,827 (Comrie references) and Zhao Yi, et al. reference each hereby incorporated by reference herein, have not afforded the various advantages and other combinations of features as presented herein. Indeed, in the prior art systems, disadvantages often exist that can create problems in a variety of areas.
For example, the Comrie references teach halogen based sorbents for coal combustion to facilitate Hg removal from the flue gas; however, such references rely on the addition of halogenated compounds, such as calcium-bromides to coal prior to combustion. Apart from being expensive, such halogenated compounds are also hazardous chemicals making their transport, use and disposal of limited desirability within the industry. Such, halogenated compounds further generally require additional remediation and disposal steps creating additional undesired cost and liabilities. For example, none of the Comrie references teach the use of segregated particulate matter, such as fly ash, and/or segregated calcium source compounds, such as limestone to achieve the synergistic catalytic removal or prevention of nitrogen, sulfur and Hg emissions resulting from coal combustion. In addition, the Comrie references are not applicable to other carbonaceous and/or feedstock based processes, such as gasification and the like. The use of these compounds may also cause slagging, fouling or corrosion of boiler tubes in a combustion furnace.
In another limited example, the Zhao Yi, et al. reference is also limiting as it uses lime as a sorbent to effectuate desulfurization and denitrification. However, use of hydrated lime as an additive is practically and commercially limited. Apart from the obvious undesirable caustic chemical profile of using such hydrated lime species, such as calcium hydroxide, such calcium sources are generally more expensive further limiting their usefulness. In addition, the Zhao Yi, et al. reference fails to provide optimal surface area understanding to any pre-combustion additives as well as their addition to a combustible fuel source reducing their actual effectiveness and preventing some functioning. Again, the Zhao Yi, et al. reference is not applicable to other carbonaceous and/or feedstock based processes, such as gasification and/or partial oxidation gasifying reactor systems (PDX).
One exemplary application of the inventive technology may include the treatment of carbonaceous materials such as coal to generate a catalytically enhanced low emission carbonaceous fuel. In one embodiment, the invention provides compositions and methods for reducing emissions of NOx, SOx and Hg among others CCB's that arise from the combustion of coal. In particular, coal burning facilities such as those used by electrical utilities may be used as one exemplary model of the current invention. In a preferred embodiment, for example a typical pulverized coal-fired facility may be appropriate for the current invention. In a typical pulverized coal fired facility, coal may be combusted in an atmospheric air combustion environment, additionally in an oxygen-fired facility, coal is combusted in an enriched oxygen environment by using pure oxygen diluted with combustion air or gas or perhaps flue gas (Hot/Cold RFG).
Again, as shown in FIG. 1, flue gas (FG), which may be a combination of combustion gases, air and various particulate matter such as fly ash may be shunted through a convection pathway where heat may be removed from the flue gases. It should be noted that, as shown in FIG. 2, such a convection pathway is generally characterized by a plurality of “heat” zones characterized by the temperature of the gases and combustion products in each zone with greater temperatures nearer the combustion event and falling generally downstream. As noted in FIG. 1, such a convective pathway may contain a variety of combustion gases, perhaps containing NOx, SOx and Hg species as well as particulate matter such as fly ash and other constituents moving away from the combustion event. In typical conventional systems as shown in FIG. 2 below, this flue gas may undergo various post-combustion treatments, such as chemical scrubbers. Post-combustion sorbant injections may be applied to the flue gas to remove undesired chemical constituents and the like prior to environmental release.
For example, again as shown in FIG. 2, typical post-combustion flue-gas treatments may include post-combustion selective catalytic reaction (SRC) treatment, traditional sorbent injection, and post-combustion flue gas desulfurization (FGD). In addition, as shown generally in FIGS. 2-3, further along in the convective pathway, the flue gas and fly ash may pass through lower temperature zones until a baghouse or electrostatic precipitator is reached before the gases may be emitted to the stack. In the US, typical remediation steps generally need to be accomplished prior to environmental release of the flue gas through the stack.
As an initial matter, coal-fired power plants generate steam produced in a boiler which is further used to generate electricity. In a steam boiler, water is heated under pressure to produce high-temperature and high pressure steam, which then passes through a steam turbine that spins an electric generator. The heat required to produce steam is obtained by burning coal. As noted above, flue gas formed after burning the coal contains hazardous emissions which are typically treated with pollutant control devices placed after combustion. There are a number of traditional post-combustion remediation methods.
Mercury speciation may have a strong impact on its capture by air pollution control techniques. Depending on the flue gas conditions Hg may be present in the flue gas as elemental mercury vapor)(Hg0), as an oxidized mercury species (Hg2+), and as particulate-bound mercury (Hgp). Elemental Hg, released into the exhaust gas, can then be oxidized to Hg2+ via homogeneous and heterogeneous oxidation reactions. Among these Hg species, Hg0 may be difficult to capture due to its insolubility in water, high volatility and chemical inertness. Different control technologies such as filters, desulfuration units and sorbent injection can be applied to decrease Hg emissions. As one example, mercury is at least partially volatilized upon combustion of coal. As a result, the mercury tends not to stay with the ash, but rather becomes a component of the flue gases. If remediation is not undertaken, the mercury tends to escape from the coal burning facility into the surrounding atmosphere. Depending on the type of coal combusted and Hg speciation, Hg removal efficiency can show significant variation making it difficult to find a consistent Hg removal technology for different types of coal burned in different types of boilers or furnaces or other fuels or fuel uses whether combustion or not.
Two common mercury removal technologies are the addition of scrubbers and carbon injection. However, each of these methods has significant technical and economical drawbacks that limit their effectiveness. In a typical carbon injection remediation process activated carbon is injected into the flue gas stream to adsorb mercury before it exits the stack. While this approach may reduce mercury emissions, it can also produce a significant amount of solid potentially hazardous waste. For example, the activated carbon systems may lead to carbon contamination of the fly ash collected in exhaust air treatments such as the bag house and electrostatic precipitators. Furthermore, since the fly ash may now contain activated carbon, it can no longer be useable in cement and/or concrete applications, one of the major post combustion utilization markets. Finally, use of such activated carbon systems tends to be associated with high treatment costs and elevated capital costs. As noted above, another typical Hg remedial technique involves the treatment of the flue gas with wet scrubber or Selective Catalytic Reduction (SCR) systems. However, again these approaches are also capital intensive—in materials and implementation—and further use hazardous materials such as anhydrous ammonia, and also produce undesired and perhaps hazardous waste products which must be disposed of, often at great expense. Moreover, the present invention may assist utilities in complying with new mercury emission regulations without the high capital equipment costs associated with current mercury remediation technologies.
Flue gas NOx emissions may be typically controlled by Selective Catalytic Reduction (SCR) systems processes. In an exemplary SCR process, ammonia (NH3) reacts with NO and NO2 gases such as on the catalyst surface and reduces to nitrogen (N2) and water vapor (H2O). Ammonia may be diluted with air or steam and this mixture may be injected into the flue gas upstream of a metal catalyst bed where it reacts with the flue gas. Oxides of vanadium, titanium, tungsten, or zeolites typically catalyze such as in the following reactions:4NO+4NH3+O2→4N2+6H2O2NO2+4NH3+O2→3N2+6H2ONO+NO2+2NH3→2N2+3H2OHowever, such methods of NOx reduction are again limited as such processes are typically expensive and require the use of, and also generate hazardous compounds/waste that may require further remediation and/or disposal. Again, the present invention may assist utilities in complying with new NOx regulations without the high capital equipment costs associated with current NOx remediation technologies.
In another remediation example, flue gas SOx removal systems may be generally separated into dry and wet removal systems depending on the particular coal's sulfur content. Plants burning low-sulfur coal typically use dry systems where lime and water are added to the flue gas and the following reactions occur:CaO+H2O→Ca(OH)2 Ca(OH)2+SO2→CaSO3.½H2O+½H2OTypically the solids formed from the SO2 reaction may be captured by electrostatic precipitators or filtration devices such as bag houses. A typical “wet” SOx removal system may typically be used in plants where high-sulfur coal is burned. Here, water sprayers may be used to saturate the flue gas, while calcium carbonate (CaCO3) is injected into the flue gas stream. Sulfur dioxide in flue gas may react with the CaCO3 and calcium sulfite (CaSO3.1/2H2O) may be formed. CaSO3.1/2H2O may be oxidized in a subsequent reaction forming calcium sulfate (CaSO4.2H2O), also known as gypsum, perhaps through the following reactions:CaCO3+SO2+½H2O→CaSO3.½H2O+CO2CaSO3½H2O+½O2+3/2H2O→CaSO4.2H2OTypical “wet” SOx removal systems however can be limited as they generally employ forced oxidation methods to push desulfurization type reactions to maximize gypsum formation. Both dry and wet SOx removal systems have high capital costs due to the need for expensive non-corrosive materials in the systems. The present invention may assist utilities in complying with new SOx regulations without the high capital equipment costs associated with current SOx remediation technologies.
The present invention may assist utilities or other users in reducing the amount of CO2 that is produced in a combustion furnace or gasification processes due to the catalytic process which improves carbon conversion efficiency. For example, particulate matter (PM) emissions consist primarily of fly ash and unburned carbon produced from burning of coal in a coal fired furnace or boiler and is generally a powdery particulate matter made of the components of coal that do not volatize upon combustion. The content and amount of ash are a function of coal properties, furnace-firing configuration and boiler operation. Depending on the boiler type, approximately 50% to 80% of the total ash exits the boiler as fly ash. PM emissions can also be formed from the reactions of SO2, NOx compounds and unburned carbon particles. PM emissions in coal-fired power plants is normally carried off in the flue gas and is usually collected from the flue gas using conventional apparatus such as electrostatic precipitators, filtration devices such as bag houses, and/or mechanical devices such as cyclones. This production of large amounts of fly ash may be used for secondary products or uses or disposed of. Various attempts to create secondary product streams from this fly ash waste, such as cement production have been met with some limited success, however, often the vast bulk of fly ash is simply land filled.
As shown above, the generally known systems and techniques for coal combustion generated NOx, SOx, Hg as well as particulate removal are limited in several significant ways. First, such systems are generally expensive requiring significant capital cost and require not only expensive but sometime dangerous chemicals. As noted above, such systems also generally produce hazardous byproducts that must be disposed of increasing such systems incremental costs. Furthermore, such systems typically require additional compliance with government regulations further driving up the cost.
Second, such systems are post-combustion processes requiring additional expensive application and removal capabilities. In addition, the effectiveness of such systems is variable and inconsistent based on the type of coal utilized at a particular plant limiting the range of coal inputs available for use at a specific plant without significant retro-fitting. Third, as noted, while some synergies do exist, no single comprehensive system exists to effectively deal with the various combustion byproducts sought to be removed.
In addition, as noted above other processes, such as gasification may also consume carbonaceous and/or other feedstocks. Such exemplary processes can occur in the presence of air, which contains nitrogen. As such, gasification reactors can create by-products that need to be treated or disposed of due to environmental concerns. For example, during the combustion process, carbon dioxide and nitrogen- and/or sulfur-containing compounds, such as oxides of nitrogen and amines, can be formed. Environmental regulations more frequently require the collection and sequestration of carbon dioxide. Amine separator units which are necessary to remove acidic compounds, such as, for example, H2S and CO2, are very energy intensive, are large and thus have a massive footprint, and can be very costly to operate and maintain. As noted above, the following invention may not only, in some embodiments reduce harmful emissions resulting from the process, but may also improve CO formation, perhaps through a catalytic and/or sorbing process or other process as will be explored below.
Additional embodiments of the inventive technology may include the treatment of carbonaceous and/or other feedstocks for use in gasification, pyrolysis and/or reformation processes. For example, “gasification” herein generally relates to a variety of gasifier systems such as GE gasifier and/or Texaco gasifier referenced generally in the attached IDS and herein incorporated in their entirety by reference. Such systems may generally utilize carbonaceous materials such as for example coal or coke to form select product gas components such as carbon monoxide, hydrogen gas or synthesis gas (syngas), which can be used to produce electricity in an integrated gasification combined cycle (IGCC) process or as a starting point in many chemical processes.
Gasification emphasis again came to the forefront due to the energy crisis of the 1970's. Gasifier technology was perceived as a relatively cheap alternative for small-scale industrial and utility power generation, especially when sufficient sustainable biomass resources were available. By the beginning of the 1980's nearly a dozen (mainly European) manufacturers were offering small-scale wood and charcoal fired “steam generation” power plants. In Western countries, coal gasification systems began to experience expanded interest during the 1980's as an alternative for the utilization of natural gas and oil as the base energy resource. Technology development perhaps mainly evolved as fluidized bed gasification systems for coal, but also for the gasification of biomass. Over the last 15 years, there has been much development of gasification systems directed toward the production of electricity and generation of heat in advanced gas turbine based co-generation units.
As shown in FIG. 1, generally the gasification process may involve the controlled heating of carbonaceous fuels and/or feedstock in the absence of oxygen or reduced oxygen, resulting in thermal decomposition of the fuel into volatile gases and solid carbon material by-product. As noted above, a typical gasifier may convert carbonaceous fuels and/or feedstock into gaseous components by applying heat under pressure in the presence of steam.
A traditional gasifier differs from a combustor in that the amount of air or oxygen available inside the gasifier may be controlled so that only a relatively small portion of the fuel burns completely. This “partial oxidation” process provides heat to further the process. Rather than burning, most of the carbon-containing feedstock is chemically broken apart by the gasifier's heat and pressure, setting into motion chemical reactions that produce primarily hydrogen and carbon monoxide, and other gaseous constituents. Such gasifier systems may involve combustion while others do not involve a combustion pathway. Gasification reactors can convert generally solid feedstocks into gaseous products. For example, gasification reactors can gasify carbonaceous feedstocks, such as coal and/or petroleum coke, to produce desirable gaseous products such as hydrogen and carbon monoxide and some amounts of methane. Gasification reactors generally need to be constructed to withstand the significant pressures and temperatures required to gasify solid feedstocks. Generally, carbon in the coal or coke can be converted into gas by partial combustion with oxygen.
In an exemplary gasification process, carbonaceous or other feedstocks undergo a combustion process as the volatile products and some of the char may react with oxygen to form carbon dioxide and perhaps a small amounts of carbon monoxide, which may further provide heat for the subsequent gasification reactions.C+O2→CO2 andC+½O2→CO
In this process carbon also can react with water in an endothermic water gas reaction to perhaps produce carbon monoxide and hydrogen, via the reaction.C+H2O→H2+CO
A shift reaction may then convert all or part of the carbon monoxide into hydrogen to reach equilibrium.CO+H2O→CO2+H2 
The results of this final mixture may comprise hydrogen and carbon monoxide and may be referred to generally to as synthesis gas or syngas. Additional general reference to various gasification examples may be found in U.S. Pat. No. 7,638,070 and the accompanying provisional IDS incorporated herein in their entireties by reference.
As will be discussed in more detail below, the present invention overcomes the limitations of the prior art and provides a novel and previously unrecognized improved treatment of carbonaceous fuel and/or feedstock sources that may result in the reduction and/or prevention of NOx, SOx and Hg emissions among other CCB's.